US20130343156A1 - Devices, Systems and Methods for Measuring Borehole Seismic Wavefield Derivatives - Google Patents

Devices, Systems and Methods for Measuring Borehole Seismic Wavefield Derivatives Download PDF

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US20130343156A1
US20130343156A1 US13/531,588 US201213531588A US2013343156A1 US 20130343156 A1 US20130343156 A1 US 20130343156A1 US 201213531588 A US201213531588 A US 201213531588A US 2013343156 A1 US2013343156 A1 US 2013343156A1
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sensors
wavefield
seismic
derivative
group
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Steve Allan Horne
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Schlumberger Technology Corp
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Schlumberger Technology Corp
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Assigned to SCHLUMBERGER TECHNOLOGY CORPORATION reassignment SCHLUMBERGER TECHNOLOGY CORPORATION ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: HORNE, Steve Allan
Priority to EP13810416.1A priority patent/EP2867706A4/en
Priority to BR112014032486A priority patent/BR112014032486A2/pt
Priority to MX2014015816A priority patent/MX2014015816A/es
Priority to PCT/US2013/045292 priority patent/WO2014004078A2/en
Publication of US20130343156A1 publication Critical patent/US20130343156A1/en
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    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/42—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators in one well and receivers elsewhere or vice versa
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/28—Processing seismic data, e.g. for interpretation or for event detection
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/10—Aspects of acoustic signal generation or detection
    • G01V2210/14—Signal detection
    • G01V2210/144—Signal detection with functionally associated receivers, e.g. hydrophone and geophone pairs
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/10—Aspects of acoustic signal generation or detection
    • G01V2210/16—Survey configurations
    • G01V2210/161—Vertical seismic profiling [VSP]
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/10—Aspects of acoustic signal generation or detection
    • G01V2210/16—Survey configurations
    • G01V2210/169—Sparse arrays
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/50—Corrections or adjustments related to wave propagation
    • G01V2210/57—Trace interpolation or extrapolation, e.g. for virtual receiver; Anti-aliasing for missing receivers

Definitions

  • the present disclosure relates to the study of underground formations and structures, for example as it relates to oil and gas exploration.
  • the present disclosure relates more specifically to seismic surveying of subterranean geological formations.
  • Borehole seismic survey systems often involve sources located at the surface and receivers placed in the well. Other configurations are possible, for example the drill bit can function as the seismic source and receivers can be placed at the surface.
  • the distance between receivers may be governed by conventional sampling theory, which prescribes that any wavefield should be sampled at greater than twice the highest frequency component in the wavefield if there is to be no loss of information. This can impose an upper limit on receiver spacing requirements if there is to be no significant loss of spatial wavenumber information. In terms of borehole seismic this implies that there is a maximum spacing between receivers that cannot be exceeded if spatial aliasing is to be avoided. For conventional borehole seismic surveys, such as Vertical Seismic Profiles (“VSP”), this spacing is about 50 ft (15 m). The number of receivers deployed downhole may be limited for economic reasons, telemetry restrictions and safety reasons.
  • VSP Vertical Seismic Profiles
  • This disclosure relates to seismic devices, systems and methods for measuring an unaliased seismic wavefield using a reduced sampling rate compared to conventional sampling theory.
  • the seismic devices, systems and methods measure an unaliased seismic wavefield using a sampling requirement that is half that of conventional theory (e.g. according to some embodiments the spacing between receivers (groups of receivers) is twice the distance suggested by conventional theory).
  • the seismic devices, systems and methods measure an unaliased seismic wavefield using a sampling requirement that that is one-third that of conventional theory (e.g. according to some embodiments the spacing between receivers (groups of receivers) is three times the distance suggested by conventional theory).
  • the device is a downhole tool that includes an array of at least two borehole seismic sensors configured to sample data corresponding to a desired wavefield and at least one of its derivatives.
  • the array includes two borehole seismic sensors configured to sample data corresponding to a desired wavefield and its first derivative.
  • the downhole tool includes an array of at least three borehole seismic sensors configured to sample data corresponding to a desired wavefield and both its first and second derivatives.
  • the array includes at least two closely-spaced, same-type borehole seismic sensors.
  • these seismic sensors can be at least two closely-spaced displacement sensors.
  • the seismic sensors can be at least two closely-spaced velocity sensors.
  • the seismic sensors can be at least two closely-spaced acceleration sensors.
  • the array includes at least two closely-spaced hydrophones, or at least two closely-spaced geophones, or at least two closely spaced accelerometers.
  • the array includes at least two co-located sensors (i.e. effectively or substantially co-located sensors) of different types.
  • the sensors can be one displacement sensor and one velocity sensor and optionally one acceleration sensor, with the sensors being co-located at the same depth level (e.g. same axial position along the shuttle or drill string).
  • the device is a downhole tool that includes an array of at least two borehole seismic sensors for sampling data corresponding to a desired wavefield and at least one of its derivatives (for example according to any one of the embodiments described herein) and the device also includes an electronics subsystem with machine-readable instructions for computing at least one wavefield derivative and/or an unaliased wavefield from the sampled data.
  • the system includes a multi-level array of sensors, where each array includes at least two borehole seismic sensors for sampling data corresponding to a desired wavefield and at least one of its derivatives, and where the inter-array distance corresponds to a spatial sampling rate that is at least half, or that is at least one-third, the sampling rate suggested by conventional theory.
  • the inter-array distance ranges from about 60 feet to about 100 feet or to about 90 feet.
  • each array is according to one of the embodiments described in connection with the devices above.
  • the system also includes an electronics subsystem including machine-readable instructions for computing the wavefield derivatives, or the unaliased wavefield, or both.
  • the method includes: deploying an array of at least two borehole seismic sensors to sample data corresponding to a wavefield and at least one of its derivatives in a borehole; firing a seismic source; collecting data at the sensors; and computing at least one wavefield derivative, or computing the unaliased wavefield, or both.
  • the method includes lowering a wireline cable into a borehole, wherein the wireline cable includes at least two shuttles and the shuttles includes at least two sensors for sampling data corresponding to a wavefield and at least one of its derivatives, and the shuttles are separated by a distance resulting in an inter-array spacing that corresponds to a sampling rate that is at least half or at least one-third that suggested by conventional theory (i.e. resulting in an inter-array spacing that is at least twice or at least three times that suggested by conventional theory); firing a seismic source; collecting seismic data; and, computing the wavefield derivatives, the unaliased wavefield or both from the seismic data.
  • the wireline cable includes only one shuttle with an array of sensors for sampling data corresponding to a wavefield and at least one of its derivatives, and data is collected when (or each time) the shuttle moves a distance corresponding to a sample rate that is at least half or at least one-third suggested by conventional theory.
  • a seismic source may be fired and data may be collected every about 60 feet to about 100 feet as the shuttle is lowered into the borehole.
  • the seismic sensors are deployed on a drill string which is lowered into a borehole as part of a Measurement-While-Drilling or Logging-While-Drilling operation.
  • the drill string includes a multi-level array with inter-array spacing corresponding to a sample rate that is at least half or at least one-third suggested by conventional theory (i.e. the distance between groups of receivers is at least twice or at least three times the distance between receivers suggested by conventional theory).
  • the drill string includes one array and measurements are taken as the drill string is lowered into the borehole and when it moves a distance (or each time it moves a distance) corresponding to a sample rate that is at least half, or at least one-third, the sampling rate suggested by conventional theory.
  • a seismic source may be fired and data may be collected every about 60 feet to about 100 feet as the drill string is lowered into the borehole.
  • FIG. 1A is a schematic illustration of a vertical seismic profiling operation that can be used with embodiments of devices, systems and methods of this disclosure.
  • FIG. 1B is a schematic illustration of another vertical seismic profiling operation that can be used with embodiments of devices, systems and methods of this disclosure.
  • FIG. 2 is a schematic illustration of a well data acquisition and logging system that can be used with embodiments of devices, systems and methods of this disclosure.
  • FIG. 3 is a schematic illustration of an embodiment of a device according to this disclosure.
  • FIG. 4 is a schematic illustration of another embodiment of a device according to this disclosure.
  • FIGS. 5A and 5B are together a schematic illustration of a conventional multi-level array of sensors as compared to a multi-level array of sensors according to an embodiment of this disclosure.
  • FIG. 6 is a graph of conventionally sampled data in the f-k domain along with a graph of the unaliased transformed data.
  • FIG. 7 is a graph of sparsely sampled data in the f-k domain along with a graph showing the consequent spatial aliasing.
  • FIG. 8 is a graph illustrating wavefield derivatives computed using a second order accurate central difference method from the closely spaced receivers in the sparsely sampled data set.
  • MWD Measurement While Drilling
  • LWD Logging While Drilling
  • MWD and LWD are used interchangeably and have the same meaning. That is, both terms are understood as related to the collection of downhole information generally, to include, for example, both the collection of information relating to the movement and position of the drilling assembly and the collection of formation parameters.
  • An “array” or “group” of sensors is a set of sensors configured to measure a wavefield and at least one of the wavefield's derivatives.
  • the “array” or “group” can be a set of sensors of different types located at the same depth level, or else the “array” or “group” can be a set of sensors of the same type that is spatially separated by an amount appropriate to acquire data from which the wavefield can be measured and at least one of the wavefield's derivatives can be computed.
  • a “multi-level array” of sensors is a set of groups of sensors (a set of sensor arrays), for example where each array or group is at a different position or depth along the borehole when deployed (e.g. each array of receivers in the multi-level array is located at a different axial position on the tool to which it is attached).
  • a wireline cable may include a set of shuttles, where each shuttle includes a group of sensors (an array) and each shuttle is at a different position along the cable. The set of shuttles then includes a multi-level array of sensors.
  • “Conventional” sampling theory refers to the theory that a wavefield should be sampled at greater than twice the highest frequency component in the wavefield if there is to be no loss of information.
  • “Conventional” devices, systems and methods are those devices, systems, and methods wherein sampling requirements are according to conventional theory. This can impose an upper limit on sensor spacing requirements if there is to be no significant loss of spatial wavenumber information.
  • a “downhole tool” can be any instrumentation used in a borehole such as a bare sensor, or a sensor deployed on a shuttle, or a sensor deployed on a MWD drill string.
  • FIG. 1A An example of vertical seismic acquisition in a borehole is illustrated in FIG. 1A .
  • a cable 21 carrying a plurality of VSP shuttles 211 is suspended from a surface 201 of a borehole 20 into the borehole 20 .
  • System noise is alleviated or avoided by pushing or wedging the shuttles against the formation 202 or any casing surrounding the wellbore 20 using a clamping or locking mechanism 212 .
  • the clamping or locking mechanism 212 can be based on the use of springs, telescopic rams or pivoting arms as shown.
  • the shuttles 211 can carry transducer elements 213 to measure the velocity or acceleration in one or three independent directions.
  • the clamping mechanism 212 ensures that the transducers 213 are coupled to the borehole wall. In a VSP operation, a significant decrease in the signal-to-noise ratio can be observed when the geophone loses contact with the wall of the borehole.
  • a cable reel 214 and feed 215 supports the cable 21 . Measurement signals or data are transmitted through the cable 21 to a base station 22 on the surface for further processing.
  • the cable 21 can be an armored cable as used for wireline operations with a plurality of wire strands running through its center.
  • a source 203 as shown is activated generating seismic waves which travel through the formation 202 .
  • part of the seismic energy may be reflected and/or refracted.
  • the transducers 213 register movements of the earth and the measurements are transmitted directly or after in-line digitization and/or signal processing to the surface base station for storage, transmission and/or further processing. The subsequent data processing steps are known and well established in the field of hydrocarbon exploration and production.
  • FIG. 1B illustrates a seismic operation similar to that of FIG. 1A except the shuttle-carrying cable 21 of FIG. 1A is replaced by a cable 25 having a plurality of internal mounts 251 where each mount can accommodate at least two hydrophones.
  • a cable 25 having a plurality of internal mounts 251 where each mount can accommodate at least two hydrophones.
  • the cable 25 (hereinafter “borehole seismic cable” or “streamer”) has the appearance of a streamer as used in marine seismic acquisitions in that the skin or outer layer of the cable has substantially the same diameter at the locations of the sensors as in between the sensors.
  • the '860 publication describes various configurations of the densely sampled groups of hydrophones to estimate gradients of the wavefield directly from the hydrophone measurements. The distance (depth interval) between these groups of hydrophones is governed by the signal sampling requirements.
  • FIG. 2 illustrates a land-based platform and derrick assembly (drilling rig) 10 and drill string 12 with a well data acquisition and logging system, positioned over a wellbore 11 for exploring a formation F.
  • the wellbore 11 is formed by rotary drilling in a manner that is known in the art.
  • the drill string 12 is suspended within the wellbore 11 and includes a drill bit 105 at its lower end.
  • the drill string 12 is rotated by a rotary table 16 , energized by means not shown, which engages a kelly 17 at the upper end of the drill string 12 .
  • the drill string 12 is suspended from a hook 18 , attached to a travelling block (also not shown), through the kelly 17 and a rotary swivel 19 which permits rotation of the drill string 12 relative to the hook 18 .
  • Drilling fluid or mud 26 is stored in a pit 27 formed at the well site.
  • a pump 29 delivers the drilling fluid 26 to the interior of the drill string 12 via a port in the swivel 19 , inducing the drilling fluid 26 to flow downwardly through the drill string 12 as indicated by the directional arrow 8 .
  • the drilling fluid 26 exits the drill string 12 via ports in the drill bit 105 , and then circulates upwardly through the region between the outside of the drill string 12 and the wall of the wellbore 11 , called the annulus, as indicated by the direction arrows 9 . In this manner, the drilling fluid 26 lubricates the drill bit 105 and carries formation cuttings up to the surface as it is returned to the pit 27 for recirculation.
  • the drill string 12 further includes a bottomhole assembly (“BHA”), generally referred to as 100 , near the drill bit 105 (for example, within several drill collar lengths from the drill bit).
  • BHA 100 includes capabilities for measuring, processing, and storing information, as well as communicating with the surface.
  • the BHA 100 thus may include, among other things, at least one logging-while-drilling (“LWD”) module 120 , 120 A and/or at least one measuring-while-drilling (“MWD”) module 130 , 130 A.
  • LWD logging-while-drilling
  • MWD measuring-while-drilling
  • the BHA 100 may also include a roto-steerable system and motor 150 .
  • the LWD and/or MWD modules 120 , 120 A, 130 , 130 A can be housed in a special type of drill collar, as is known in the art, and can contain at least one type of logging tools for investigating well drilling conditions or formation properties.
  • the logging tools may provide capabilities for measuring, processing, and storing information, as well as for communication with surface equipment.
  • the BHA 100 may also include a surface/local communications subassembly 110 , which enables communication between the tools in the LWD and/or MWD modules 120 , 120 A, 130 , 130 A and processors at the earth's surface.
  • the subassembly 110 may include a telemetry system that includes an acoustic transmitter that generates an acoustic signal in the drilling fluid (a.k.a. “mud pulse”) that is representative of measured downhole parameters.
  • the acoustic signal is received at the surface by instrumentation that can convert the acoustic signals into electronic signals.
  • the generated acoustic signal may be received at the surface by transducers.
  • the output of the transducers may be coupled to an uphole receiving system 90 , which demodulates the transmitted signals.
  • the output of the receiving system 90 may be coupled to a computer processor 85 and a recorder 45 .
  • the computer processor 85 may be coupled to a monitor, which employs graphical user interface (“GUI”) 92 through which the measured downhole parameters and particular results derived therefrom are graphically or otherwise presented to the user.
  • GUI graphical user interface
  • the data is acquired real-time and communicated to the back-end portion of the data acquisition and logging system.
  • the well logging data may be acquired and recorded in the memory in downhole tools for later retrieval.
  • the LWD and MWD modules 120 , 120 A, 130 , 130 A may also include an apparatus for generating electrical power to the downhole system.
  • an electrical generator may include, for example, a mud turbine generator powered by the flow of the drilling fluid, but other power and/or battery systems may be employed additionally or alternatively.
  • the well-site system is also shown to include an electronics subsystem having a controller 60 and a processor 85 , which may optionally be the same processor used for analyzing logging tool data and which together with the controller 60 can serve multiple functions.
  • the controller and processor need not be on the surface as shown but may be configured in any way known in the art.
  • the controller and/or processor may be part of the MWD (or LWD) modules on which the sensor array according to this disclosure may be positioned.
  • the electronics subsystem may include machine-readable instructions for computing at least one wavefield derivative, and/or reconstructing an unaliased wavefield (i.e. reconstructing data at virtual or interpolated receivers).
  • the devices, systems and methods according to this disclosure are applicable to both wireline and MWD operations, and any other method of borehole investigation for example methods involving lowering streamers including borehole seismic sensors into the wellbore.
  • the devices, systems and methods according to this disclosure may be adapted for use in vertical, deviated and horizontal wellbores.
  • the devices, systems and methods according to this disclosure may also be adapted for use in nearly any downhole seismic acquisition system, for example, wireline Vertical Seismic Profiles (“VSP”), cross-well seismic, “seismic-while-drilling” and “passive seismic” (in either case where receivers may be deployed along the drill string), among other borehole seismic techniques.
  • VSP wireline Vertical Seismic Profiles
  • cross-well seismic cross-well seismic
  • “seismic-while-drilling” in either case where receivers may be deployed along the drill string
  • passive seismic in either case where receivers may be deployed along the drill string
  • the devices, systems and methods according to this disclosure may also have
  • the present disclosure provides devices, systems and methods which reduce the sampling requirement for seismic operations.
  • Conventional sampling theory suggests that any wavefield should be sampled at greater than twice the highest frequency component in the wavefield if there is to be no loss of information. This can impose an upper limit on sensor spacing requirements if there is to be no significant loss of spatial wavenumber information.
  • the sensor spacing is chosen to have at least two samples per maximum frequency in the wavefield of interest (alternatively at least two samples per shortest wavelength in the wavefield of interest.)
  • this spacing is about 50 ft (15 m).
  • the sampling requirement is reduced to sampling at discrete intervals at or above the highest spatial frequency in the data.
  • the sampling requirement can be reduced by half (e.g. the distance between receivers—or in the present case, the distance between receiver groups—is doubled).
  • the sensor spacing can be increased to about 100 ft (30 m) without loss or substantial loss of information.
  • This arrangement may be, for example, advantageous in MWD services or Wired Drilled pipe applications or other services where sensor spacing is primarily driven by drilling logistics and physical restrictions.
  • This disclosure provides devices and systems, for example including configurations of receivers and multi-level receiver arrays for sampling data corresponding to a desired wavefield and at least one of its derivatives, and methods for computing wavefield derivatives and reconstructing from the wavefield and wavefield derivative data the unaliased wavefield.
  • the multi-channel sampling theory extends the Shannon-Nyquist theory to situations where measurements are available of both the signal and also the signal's derivative(s):
  • the sampling requirement is half of that compared to the case when only the signal is measured. Furthermore, in the case that higher order derivatives are available, the sampling requirement becomes even sparser. For example, in the case that a signal and its first and second order derivatives are available, the signal need be sampled at a third of the rate compared to the case that only the signal itself is available. While equations 1 and 2 above are written in terms of spatial sampling, the same equations also apply to temporal sampling.
  • the present disclosure provides devices, systems and methods for measuring wavefield derivatives.
  • the devices and systems include sensor groups configured according to spatial sampling requirements for measuring wavefield derivatives, and sensor groups configured according to temporal sampling requirements for measuring wavefield derivatives.
  • the methods include methods of using such devices and systems, including to generate data that is substantially free from aliasing.
  • the device includes an array of sensors for acquiring data corresponding to a wavefield and at least one of the wavefield's derivatives. In some embodiments, the device includes an array of sensors for acquiring data corresponding to a wavefield and its first derivative. In some embodiments, the device includes an array of sensors for acquiring data corresponding to a wavefield and its first and higher order derivatives. In some embodiments, the device includes an array of sensors for acquiring data corresponding to a wavefield and its first and second derivatives.
  • devices which acquire such data according to temporal sampling requirements generally include an array of at least two different, co-located sensors. “Different” means that one sensor measures the wavefield signal and the other sensor or sensors measure wavefield derivatives. “Co-located” means that the sensors are located at the same depth level (e.g. axial position along the shuttle to which they are attached). Systems which acquire such data according to temporal sampling requirements generally include two arrays of at least two different, co-located sensors, where the inter-array distance is according to conventional theory (i.e. the inter-array spacing is chosen to have at least two samples per maximum frequency in the wavefield of interest or at least two samples per shortest wavelength in the wavefield of interest).
  • the “inter-array distance” is measured from the central point in one group of receivers to the central point in another group of receivers.
  • the inter-array spacing matches that of conventional devices, the temporal sampling requirement is cut in half for each individual sensor in an array having displacement and velocity sensors (i.e. half the data need be collected in a given time frame for each sensor versus conventional devices), and is cut in a third for each individual sensor in arrays further having acceleration sensors (i.e. a third of the data need be collected in a given time frame for each individual sensor versus conventional devices).
  • devices which acquire such data according to spatial sampling requirements generally include an array of at least two same-type, closely-spaced sensors. “Same-type” means that the sensors measure one of displacement, velocity, or acceleration or otherwise make the same measurement. “Closely-spaced” means that the sensors are effectively at the same depth level, however they are axially staggered one from the other such that at least one wavefield derivative may be computed from the data collected by the array. Generally speaking, this means the sensors should be staggered by at least a minimum distance but not more than a maximum distance. The minimum and maximum distance can be determined by a person of skill based upon reading this disclosure. Also, generally speaking, the number of sensors in an array is one more than the highest order derivative desired. For example, two sensors are used to sample data corresponding to the wavefield and the first wavefield derivative, and three sensors are used to further sample data corresponding to the second wavefield derivative.
  • the device includes an array of at least two substantially (effectively) co-located sensors, where at least one sensor measures a wavefield and at least one sensor measures a derivative of the wavefield.
  • the wavefield can be measured using a geophone which measures the particle velocity, denoted v(t).
  • the seismic signal may also be recorded using accelerometers which measure the wavefield's particle acceleration, a(t) which is the second derivative of the displacement and the first derivative of the particle velocity.
  • the displacement associated with a seismic wavefield can also be measured.
  • the array may include: a sensor that measures displacement; and, a sensor that measures velocity; and, optionally the device may further include a sensor that measures acceleration.
  • the array includes a displacement sensor and a velocity sensor, the signal need only be recorded at half the sampling frequency compared to the case that the signal is recorded with either sensor alone.
  • the sampling rate can be further reduced to a third of the original sampling rate.
  • the displacement sensors, velocity sensors, and acceleration sensors can be any sensors suitable for use in acquiring borehole seismic information.
  • the velocity sensors may be geophones and the acceleration sensors may be accelerometers.
  • the device includes an array of closely-spaced, same-type sensors.
  • the array includes at least two closely-spaced geophones, or at least two closely-spaced hydrophones, or at least two closely-spaced accelerometers.
  • the array includes at least three closely-spaced, same-type seismic sensors.
  • “closely-spaced” is the distance (range of acceptable distances) between sensors in an array that permits a first wavefield derivative to be computed from the acquired data. In some embodiments, “closely-spaced” is the distance (range of acceptable distances) between sensor arrays that permits at least a first and a second wavefield derivative to be computed from the acquired data. In some embodiments, “closely-spaced” is the distance (range of acceptable distances) that permits at least a first derivative (i.e. permits a first derivative and possibly at least one higher order derivative) to be computed from the acquired data.
  • the intra-array spacing (the distance between sensors in a given array) is about 1 ⁇ 4 the wavelength of the shortest wavelength of interest. In some embodiments, the intra-array spacing is no more than about 0.5 m.
  • a person of skill, after reading this disclosure, should be able to determine appropriate intra-array spacings taking into account the goal of computing wavefield derivatives and transformed wavefield data that is substantially unaliased from the wavefield and derivative data, and taking into account, for example, tool restrictions, formation velocity, and other appropriate/relevant parameters.
  • Devices including sensor arrays for sampling data corresponding to a desired wavefield and at least one of its derivatives may further include an electronics subsystem for computing wavefield derivatives from the sampled data and/or for reconstructing data at a virtual receiver from the wavefield and derivative data.
  • One way of measuring the derivative of the wavefield is to use an array of closely-spaced sensors and compute the wavefield derivatives using finite difference approximations. In the case that two closely-spaced geophones are available, for example, then the second order accurate centered finite difference approximation of the wavefield's spatial derivative is:
  • More accurate spatial derivatives and higher order derivatives can also be derived in the case that more geophones are available in the closely-spaced array. For example, in the case that five receivers are available then the centered finite difference approximation of the wavefield's derivative is:
  • FIGS. 3 and 4 are schematic illustrations of non-limiting exemplary tools useful for borehole seismic surveying according to this disclosure.
  • FIG. 3 is a conceptual tool sized to fit in a borehole and including two sets of three receivers, where the intra-receiver spacing in each set is about 0.5 m.
  • the tool includes three accelerometers where adjacent accelerometers are axially-spaced about 0.5 m from each other, and three hydrophones, where adjacent hydrophones are axially-spaced about 0.5 m from each other.
  • Such a configuration may provide redundancy in data and may improve accuracy.
  • FIG. 4 provides a conceptual seismic shuttle including three sets of 3C receivers spaced approximately 0.5 m apart.
  • an additional multi-level array of receivers for example a multi-level array of hydrophones, may be interspersed with the first multi-level array to provide redundancy.
  • Devices, or groups of sensors described according to this disclosure which permit measuring data corresponding to a wavefield and its derivative(s), enable systems and methods for sampling seismic data at greater than conventional spatial separation (increased inter-array spacing) or greater than conventional temporal separation (increased time between data sampling), but nevertheless permit reconstruction of an unaliased (substantially unaliased) wavefield comparable to conventional results.
  • systems and methods can be developed where sampling requirements are reduced by at least half that of conventional systems and methods, for example systems can be designed with sensor spacing in borehole seismic applications of about 100 ft (30 m) versus about 50 ft (15 m), or measurements can be taken every about 100 ft (30 m) versus every about 50 ft (15 m), without resulting in any loss or substantial loss of information.
  • Systems which acquire such data according to spatial sampling requirements can include two arrays of at least two same-type, closely-spaced sensors, where the inter-array distance is increased relative to conventional theory.
  • the inter-array spacing for spatially-configured devices may be twice that of conventional devices for arrays having two same-type, closely-spaced sensors, and may be three times that of conventional devices for arrays having three same-type, closely spaced arrays.
  • the systems may further include an electronics subsystem having machine-readable instructions for computing wavefield derivatives and/or for reconstructing data that is substantially free of aliasing, for example comparable to systems acquiring data according to conventional sampling requirements (e.g. according to the Shannon-Nyquist theory).
  • VSP downhole seismic recordings
  • Such surveys are typically obtained using a seismic source deployed on the surface and deploying a multi-level array of geophones (or accelerometers) in a borehole where the spacing between the receivers is selected to avoid spatial aliasing. This spacing can range from about 10 m to about 15 m (30 ft to 50 ft).
  • a finer sampling can be achieved by acquiring two sequential surveys with the downhole seismic array shifted in depth. The resulting merged dataset created from the interleaving of the two datasets has an effective finer sampling.
  • such datasets are subject to changes during the two acquisitions, for example, due to sea swell in marine acquisitions.
  • an array of borehole seismic sensors can be deployed downhole, including from about 40 to about 100 shuttles with each shuttle containing one set (group) of sensors.
  • the disclosure provides systems of downhole arrays with increased sensor spacing as compared to what is suggested by conventional theory.
  • This disclosure also provides methods of obtaining unaliased (substantially unaliased) wavefield data despite sampling data using greater spatial or temporal separation as compared to what is suggested by conventional theory.
  • the systems/methods are not limited to implementation in shuttles or MWD, but can apply to any arrangement where wavefield derivatives can be measured/computed and those derivatives can be used to interpolate data at “virtual” positions.
  • the present disclosure may allow increasing, for example doubling or tripling, the effective depth span covered by an array of sensors (e.g. an array of shuttles or an array of sensors along a drill string).
  • the “missing” depth levels can be recovered using interpolation from the sensor groups (e.g. from the shuttles) where wavefield and its derivative(s) are measured.
  • a conventional arrangement may include 8 shuttles, each about 15 m apart.
  • the resulting aperture (depth span) is about 105 m.
  • the aperture could be, for example, doubled to about 210 m without loss or substantial loss of information (for example because the sampled data may be used to reconstruct the data at “virtual” shuttles—as if 16 shuttles were used although only 8 shuttles are deployed), resulting in sampling a greater length of the borehole in one experiment.
  • VSP dataset using finite difference modeling is created.
  • the source is located just below the surface and receivers are located directly below the source at a depth of 1005 m.
  • the first modeling scenario corresponds to a wireline VSP acquisition
  • the second scenario corresponds to an MWD acquisition where the receiver interval is determined by the stand length of the drill pipe (typically 90 ft).
  • the source wavelet used is a Ricker wavelet with a peak frequency of 15 Hz.
  • the direct P-wave arrives at the shallowest receiver at about 0.4 seconds and the moveout over the multi-level array is linear as the multi-level array is vertical, the model is 1D and the source lies directly above the receiver (see FIG. 5A ).
  • a secondary SV-wave arrives at the shallowest receiver around 0.85 seconds.
  • This data is transformed into the f-k domain (frequency-number) as shown in FIG. 6 .
  • the P-wave arrivals transform into the linear feature lying along the line annotated at 2.5 km/s.
  • the SV-wave arrivals transform into the subtle linear feature aligned along the line annotated at 1.25 km/s.
  • the data from the first scenario can be decimated by two, i.e. every other receiver level is removed (see FIG. 5B ).
  • the f-k transformed data shows aliasing effects (see FIG. 7 ) for both the P and SV data.
  • the data are aliased at frequencies above 40 Hz while the slower SV arrivals are aliased above frequencies of 20 Hz.
  • the multi-level array is modified to include a multi-level array of sensor groups, i.e. if additional sensors are deployed 0.5 m above and below each original receiver (forming sensor groups with a central receiver and a receiver 0.5 m above the central receiver and a receiver 0.5 m below the central receiver) ( FIG. 5B , inset)
  • the wavefield derivative can be computed using finite differences (or other suitable signal processing algorithms), see FIG. 8 .
  • the unaliased wavefield at intermediate spatial locations can then be reconstructed thereby overcoming the limitations that may be imposed by the MWD environment.

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EP13810416.1A EP2867706A4 (en) 2012-06-25 2013-06-12 DEVICES, SYSTEMS AND METHOD FOR MEASURING SEISMIC WAVY FIELD DERIVATIVES IN BORING HOLES
BR112014032486A BR112014032486A2 (pt) 2012-06-25 2013-06-12 dispositivo para levantamento sísmico de poço, sistema para levantamento sísmico de poço, e método para levantamento sísmico de poço
MX2014015816A MX2014015816A (es) 2012-06-25 2013-06-12 Dispositivos, sistemas y métodos para medir derivadas de campo de ondas sísmicas de pozos.
PCT/US2013/045292 WO2014004078A2 (en) 2012-06-25 2013-06-12 Devices, systems and methods for measuring borehole seismic wavefield derivatives

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BR112014032486A2 (pt) 2017-06-27
EP2867706A2 (en) 2015-05-06

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